Having reference to FIG. 1, a wellbore is been drilled to or through a formation or zone of interest. The zone of interest is sometimes identified roughly by a localized increase in the drill bit's rate of penetration ("ROP") or by a the detection of hydrocarbon gas with at a total gas ("TG") detector, which draws a sample of gas carried by the drilling mud when it returns to the surface.
Once the zone of interest is identified it is necessary to establish an understanding of the zone's ability to produce fluids. Production testing is accomplished by performing a prior art drill stem test or DST to establish the performance or productivity of a zone of interest in a formation.
For the DST, the wellbore is sealed above and below the zone of interest using packers. In order to set the packers, the rig must first trip out the drilling string and bit to allow a test tool to be attached to the bottom of the drill string. The drill string and tool is then reinserted into the wellbore. String weight is applied to expand the packers. Ports are opened in the tool exposing recorders to the pressure in the formation. Pressure and time are recorded for a variety of conditions, for example: initial hydrostatic (mud column) pressure, closed in pressure, flowing pressure when the tool is opened, final flowing pressure before closing the tool, closed in pressure and final hydrostatic pressure. After the test, the drill string must be tripped out of the well again to remove the tool and then run in again for reinserting the drill bit should the operator wish to continue drilling.
This DST is a time consuming and expensive process resulting in loss of valuable drilling time. Typically each trip out of the wellbore and back in can take a day meaning a loss of two days each time a DST is ordered. Further, the testing may take another day and DST specialists can cost upwards of $10,000 for each test.